The power grid is generally considered to be composed of two logical regions, the Transmission Grid(s) and the Distribution Grid(s). The Transmission Grid originates at large generation points such as hydroelectric dams, nuclear reactors, wind farms, and coal-fired or gas-fired power plants. Power from the generation point is transmitted as high-voltage alternating current (AC) over a loosely connected network of long, high-voltage lines to points where demand for power exists, such as factories, farms, and population centers. At the edges of the Transmission Grid there is a collection of Distribution Substations. Distribution Substations contain one or more Substation Transformers, which step down the voltage from high transmission line levels (typically 130 kV to 700 kV) to the medium voltage levels (typically from 4 kV to about 35 kV) at which power is distributed to consumers within a distribution service area. At the edge of the Distribution Grid are a number of Service Transformers, which transform the medium voltage of the distribution grid to the low voltages (in the US, typically 120V, 208V, 240V, 277V, or 480V). Other voltages in addition to some of these can be used elsewhere in the world. In some cases, a tier of one or more transformers, called step-down transformers, lying schematically between the Substation Transformers and the Service Transformers, create intermediate voltage reductions between the Substation and the Service Transformers. Each Service Transformer powers one or more metered loads. A load can be a dwelling, a commercial or industrial building, an element of municipal infrastructure such as a series of street lamps, or agricultural apparatus such as irrigation systems. A typical distribution grid includes other elements used to balance and regulate the flow of power. Examples of such elements are capacitor banks, voltage regulators, switches, and reclosers. FIG. 1 illustrates a typical segment of the power grid.
Distribution grids have been designed and deployed in a variety of topological configurations. In the United States, distribution grid types are typically characterized as radial, loop, or networked. Other emerging cases are the campus grid and the microgrid. Additional topologies, not described, are used elsewhere in the world.
FIG. 2a is a topological schematic of a typical radial grid. In a radial grid, a substation has one or more substation transformers. Each substation transformer has one or more substation busses. One or more three-phase feeders “radiate” outward from each substation bus, with single-phase, double-phase, or three-phase lateral lines branching off from the feeders, and tap-off points (or simply “taps”) in turn branching from the laterals. Radial grids are inexpensive to design and build because they are simple, but they are most vulnerable to outages because they lack redundant power paths, so that any break causes at least one load to lose power.
FIG. 2b is a topological schematic of a typical loop distribution grid. In a loop grid, each end of select feeders is attached to a power source such as a bus of a substation transformer. If the loop is undamaged, then power is available at all loads if either substation transformer is operational. If there is a break in the loop, then power is available at all loads assuming that both transformers are operational. In normal circumstances, a system of switches is used to ensure that only one substation transformer at a time is delivering power to each segment of the grid.
FIG. 2c is a topological schematic of a typical networked grid. This topology has maximum redundancy. In addition to employing multiple power sources, all the service transformers are linked to one another on the secondary side in a mesh arrangement. Multiple breaks in connectivity are required to cause a power outage at any point. Networked grids are most expensive to build and maintain, and are typically used in major urban areas such as Manhattan or Washington, D.C. where high-value, high-criticality loads are concentrated together.
FIG. 2d shows a microgrid or campus network. Microgrids are not traditional in electrical distribution technology, but are emerging as a response to increased focus on energy conservation and on distributed generation of energy from renewable sources. Many variations are possible. This type of grid is typically attached to, but severable from, a wider distribution grid, and may contain its own power sources such as windmills, solar panels, or rechargeable storage batteries as well as loads. The entire network may employ low-voltage lines.
A distribution substation receives high-voltage power from the transmission grid into one or more large power transformers. A distribution transformer may incorporate a type of regulator called a load-tap changer, which alters the voltage the transformer delivers to a power distribution bus (the substation bus) by including or excluding some turns of the secondary winding circuit of the transformer, thereby changing the ratio of input to output voltage. One or more feeders depend from the substation bus. If too many feeders are required, additional transformers and busses are used.
In order to monitor and control the components of the grid, current transformers (CTs) or other current sensors such as Hall-effect sensors are attached to power-bearing conductors within the substation. The CTs output a low current on a looped conductor which is accurately proportional to the current delivered at the high voltage conductor being monitored. These low-current outputs are suitable for connecting to data acquisition subsystems associated with Supervisory Control and Data Acquisition (SCADA) systems in the substation. Primary monitoring CTs are designed and built into the substation, because changing or adding CTs to the high-voltage components is impossible or dangerous while current is flowing. On the other hand, additional CTs may be safely added to the low-current SCADA loops as needed without impacting power delivery.
In addition to the power lines themselves, the distribution grid contains numerous other devices intended to regulate, isolate, stabilize, and divert the flow of power. These devices include switches, reclosers, capacitor banks (usually for power factor correction), and secondary voltage regulators. All these devices affect the behavior of the distribution grid when considered as a data-bearing network, as do the various loads and secondary power sources on the grid. Devices that have abrupt state changes will introduce impulse noise on the grid, as can loads turning on and off. Some devices, such as transformers and capacitor banks, filter and attenuate signals at certain frequencies.
Other than the wires connecting a consumer load and the associated meter to a service transformer, the service transformer is the outermost element of the distribution grid before the power is actually delivered to a consumer. The meter is attached at the point where the power from the service transformer is delivered to the consumer. Service transformers can be three-phase, dual-phase, or single phase, as can meters.
Traditionally, reading meters was one of the largest operational costs incurred by electrical utilities. Original electric meters were analog devices with an optical read-out that had to be manually examined monthly to drive the utility billing process. Beginning in the 1970s, mechanisms for digitizing meter data and automating its collection began to be deployed. These mechanisms evolved from walk-by or drive-by systems where the meter would broadcast its current reading using a short-range radio signal, which was received by a device carried by the meter reader. These early systems were known as Automated Meter Reading systems or AMRs. Later, a variety of purpose-built data collection networks, employing a combination of short-range RF repeaters in a mesh configuration with collection points equipped with broadband backhaul means for transporting aggregated readings began to be deployed.
These networks were capable of two-way communication between the “metering head-end” at a utility service center and the meters at the edge of this data collection network, which is generally called the Advanced Metering Infrastructure or AMI. AMIs can collect and store readings frequently, typically as often as every 15 minutes, and can report them nearly that often. They can read any meter on demand provided that this feature is used sparingly, and can connect or disconnect any meter on demand as well. AMI meters can pass signals to consumer devices for the purpose of energy conservation, demand management, and variable-rate billing. Because the AMI network is separate from the power distribution grid, AMI meters are neither aware of nor sensitive to changes in the grid topology or certain conditions on the grid. Nonetheless, the introduction of AMI is generally considered to be the beginning of the Smart Grid.
Many characteristics of the electrical distribution infrastructure have limited the success of efforts to use the grid itself as a communications medium. First, the grid is a noisy environment. As already noted, state changes in loads on the grid as well as control and regulation artifacts on the grid itself cause impulse noise on the power line. Normal operation of loads like electrical motors, simple variations in the overall load, and ambient RF noise (chiefly from lightening and other weather-related causes) add up to significant Gaussian noise. The measured noise floor at a typical substation in the United States sits at about 80-90 dB below the maximum amplitude of the 60 Hz fundamental. The complex impedance of the grid varies across both the frequency and time domains. This may lead to loss of signal at a receiver sited at a higher voltage point on the grid when impedance increases, or alternately force the transmitter to use more energy than would be necessary on the average. Capacitor banks sited at points along the grid for the purpose of optimizing the power factor can cause signal attenuation. Most significantly, transformers act as low-pass filters, dramatically attenuating signals above a certain frequency. The threshold frequency is not the same on every distribution grid, because different arrangements and types of transformers are employed and because the transformers themselves are not deliberately tuned to filter at a specified frequency. All these variables impact the frequency response of the medium.
Additionally, injecting modulated current signals on the grid may cause interference between the injected signals themselves. One problematic phenomenon is crosstalk, where a signal injected on one power line is detectable on another line. When crosstalk occurs on two or more phases of the same feeder, it can be caused by inductive and capacitive coupling, as the phase lines run alongside one another for most of the length of the feeder. Crosstalk may also be due to multiple phase windings on the same transformer core. Feeder-to-feeder crosstalk has also been measured, and may be caused by reflection of the injected signal off the power bus at the substation. Given the complexity, diversity, and age of the distribution grids in the United States and the world, less is known about these phenomena than might be expected.
Finally, using the distribution grid as a communications medium often has side effects which interfere with the primary purpose of the grid, which of course is delivering clean, reliable power to consumers. If devices under power resonate with an injected current, a phenomenon called flicker results. LED, CFL, incandescent and fluorescent lighting visibly flickers in response to certain frequencies. This is annoying and sometimes dangerous, as visual flicker has been demonstrated to cause both seizures and vertigo. Other types of devices, such as fans and speakers, also resonate at certain frequencies, causing an audible hum. ANSI/IEEE standard 519 requires any device (whether intended as a communication device or not) that injects current on the grid to avoid doing so at certain frequencies and amplitudes to avoid causing flicker. Specifically, ANSI/IEEE standard 519 requires that no noise be added to the odd harmonics of the fundamental at or below the eleventh harmonic.
Despite the many engineering difficulties inherent in using the power grid as a communications medium, it has remained attractive to electrical utilities because the utility already owns the infrastructure, and it is present at all the points where the utility needs to collect data. Further, the regulatory and cost structure of publicly owned utilities (POUs) strongly favors them using owned assets (which can be profitably purchased and maintained via service rate increases) as opposed to paying operating expenses to a third-party communications provider such as a telephone or cable provider.
High-frequency transmissions (above 1 MHz) are attractive because theoretically high data rates can be achieved. Such schemes, called BPL for Broadband over Power Lines, offer a potential theoretical bandwidth sufficient to deliver internet access to consumers via a gateway located in their electrical meter. In the early years of the twenty-first century, the Federal Communications Commission (FCC) in the U.S. actively promoted the concept of “Access BPL” as a means of delivering high-speed Internet access to rural American families. Long-range transmission of BPL signals, however, is impractical and expensive, because every transformer between the transmitter and the receiver must be fitted with a bypass or repeater mechanism, or the low-pass filtering characteristics of the transformer will block the signal. In the United States, where the number of consumers per service transformer tends to be very small—in rural areas often only one—the cost to implement BPL becomes prohibitive. Additionally, RF interference caused by BPL transmission has created opposition from aviation, commercial radio, amateur radio, and other sectors. The FCC has attempted to be supportive of BPL technology, but new compromise rules requiring BPL installations to be capable of notching out (avoiding) frequencies where interference is reported have increased the complexity of managing a BPL service. Several attempts at deploying BPL consumer services have been abandoned.
Under the umbrella name Power Line Communication or PLC, some medium-frequency power line protocols have been used with success for Smart Grid applications, especially in Europe (and other locales with European-style grid architectures), where the number of consumers per service transformer is much larger than in the United States. The two most commonly used medium-frequency PLC initiatives are PRIME and G3, both promoted by commercial alliances based in Europe. PRIME uses orthogonal frequency-division multiplexing (OFDM) at the physical layer, with 512 differential phase-shift keyed channels (DPSK). PRIME achieves data rates as high as 128.6 kbps, but is most reliable at 21.4 kbps. Its frequency range is 42-89 kHz. G3 uses a similar physical-layer combination of OFDM and DPSK, offering 256 channels between 35 and 91 k Hz with a data rate of 33.4 kbps. Both G3 and PRIME are still sharply attenuated by transformers, though in most cases a receiver located on the medium-voltage side of a service transformer can successfully read meter transmissions from low-voltage sites served by that transformer, provided that the receiver is sited close enough to the service transformer. For these reasons, Smart Grid technologies based on these protocols are common in Europe and Asia. PLC protocols are also well-adapted to short-range power-line applications such as arbitrating the charging of electric vehicles.
At the other end of the spectrum are ultra-low frequency systems, chiefly used for control systems because they have little data-bearing capacity. Audio Frequency Ripple Control (AFRC) systems are used mostly in rural areas for load management: to turn off high-consumption devices such as electric heaters and air conditioners during peak load times, or to control use of other constrained resources, such as automated farm irrigation systems. An AFRC transmitter sits on the high-voltage side of a substation or transmission transformer and may service multiple substations. AFRC data rates vary from 2 to 10 bits per second, and the maximum message length is about 100 bits. After such a transmission, the transmitter requires a long idle period before it can transmit again, with a maximum duty cycle on the order of 10%. AFRC systems cause obvious flicker, but not at a dangerous frequency. Because they are typically used in areas of low population density and transmissions are infrequent, the side effects are tolerated. AFRC is a broadcast technology operable from high voltage to low voltage and thus cannot be used for collecting meter data or other data about edge conditions, because that requires transmitting from low voltage to higher voltage.
Aclara®'s TWACS® technology operates by injecting pulses onto the power line when the fundamental power carrier crosses the zero point—twice per 50 Hz or 60 Hz cycle. This method operates either from substation to edge or edge to substation, and uses a polling protocol to avoid having one edge transmission interfere with another. It is slow because it is tied to the fundamental, and because of the polling architecture. It has been criticized by consumer groups for the amount of impulse and broadband noise it introduces onto the grid.
Landis+Gyr employs a low-cost, low-frequency edge transmitter originally developed by Hunt technologies, intended to operate in conjunction with AFRC to provide two-way communication over long distances on the grid. The data transmission method using this transmitter is cheap and reliable, but limited. It induces sympathetic current oscillations by connecting variable impedance to the power line. The data rate is low because the transmitter is dependent on a voltage relative to the power carrier, so that only a few pulses can be injected per 50 Hz or 60 Hz cycle. To achieve enough redundancy for detection at the receiver, the same signal must be repeated for several cycles, resulting in a data rate measurable in cycles per bit rather than bits per cycle. The method is also very noisy, in that each pulse resonates across a broad frequency band.
Despite their limitations, low-frequency systems such as those from Aclara and Landis+Gyr have achieved market penetration in rural areas where wireless systems are cost-prohibitive.
The problems with, and limitations of, the high, medium, and low-frequency PLC methods as discussed above have led in the 21st century to rapid development of custom built wireless networks for AMI data collection in the U.S. High-frequency on-grid methods have proven to be too expensive, not sufficiently reliable, and too fraught with error and uncertainty to be commercially viable. Low-frequency methods can be implemented with low-cost edge-to-substation transmitters, but these lack the data-bearing capacity required by modern AMI, and on-grid low-frequency substation-to-edge transmitters like AFRC are large, expensive, and have undesirable side effects which limit their use in urban settings. One possible option would be to use high-frequency substation-to-edge transmitters in conjunction with low-frequency edge-to-substation transmitters. However, in the U.S. market forces have led to the rapid penetration of wireless AMI systems, especially in urban and suburban areas.
Cost constraints and availability of unregulated spectrum have dictated the use of mesh architectures at the edge of the AMI networks, with neighborhood concentrators that collect data from the meters and use traditional infrastructure (fiber or cellular) for backhaul to data centers. Mesh architecture means that although the RF transceivers used have individually high data rates, the edge networks are easily saturated. Most of the available data bearing capacity in these networks is used just for reporting meter interval data, with limited capacity reserved for firmware updates and control packets for applications such as demand management.
Two major factors limit the utility of the existing AMI infrastructures. The first is, of course, the capacity limitations of the mesh. The second, and more significant, is the fact that the AMI network is not congruent with the electrical grid. It is capable of providing little information about the operational state of the grid. This is unnecessary for meter reading, but more sophisticated Smart Grid applications for energy conservation, asset protection, load balancing, fault isolation, and recovery management require accurate information about the schematic relationship of grid assets, load and conditions on the several segments of the grid, and the current state of bi-modal and multi-modal assets. This information, together with the geospatial locations of the same assets, is called the Grid Map.
Utilities typically maintain two maps or models of the Grid. A Physical Network Model (PNM) aggregates the geospatial location of the assets on the grid. PNMs, thanks to modern GPS technology, are reasonably accurate with respect to point assets such as substations, capacitor banks, transformers, and even individual meters. Inaccuracies stem from failure to update the maps when repairs or changes are made. For example, a service transformer may move from one side of a street to the other as a result of street widening. Longitudinal assets, especially buried cables, are less well represented in the PNM. The PNM can contain as-designed data, but since in many places the cable was laid before global positioning technology had matured, the designs were based on ground-level survey, and the original maps may or may not have been updated to reflect changes. Subsequent surface changes complicate the problem of verifying the geographic path taken by medium-voltage distribution lines.
The second model is the Logical Network Model, or LNM. LNMs describe how grid components are connected, without reference to their geospatial location. The LNM changes frequently. During the course of repairs, the way transformers attach to taps and laterals, and meters attach to transformers, may be altered. Such changes affect both the LNM and the PNM. In many utilities, such changes are recorded manually by field agents. The manual reports may or may not be updated in the LNM and PNM, and when updates are made the time lag between maintenance occurring and its being recorded is variable. Additionally, many grid components, especially regulators, switches and reclosers, change state automatically. Unless these components are instrumented with communications back to a data center rather than simply being subject to local control systems, such dynamic changes are not reflected in the LNM. They do, however, affect the power path, the load and environmental stress on other components of the distribution grid, and the service level to consumers.
Examples of significant but not reliably known aspects of the (actual) Grid Map are the feeder and phase by which each meter is currently powered, the relative load on each phase of each feeder, especially on subordinate branches (laterals) of the grid, the actual voltage supplied to each meter, the power factor along the edges of the grid, whether all the power drawn at a transformer is metered, and the state of switch sets, especially after a weather event that has caused outages. If this information were reliably known, utilities could conserve energy, much of the savings from which would pass on to consumers, save maintenance costs, prolong the life of equipment in the field, improve the efficiency and life of utility and consumer equipment, avoid outages, and reduce recovery times after unavoidable outages.
The problem of automated, dynamic grid mapping is not solved by wireless Smart Meters. Smart meters can measure and record current, voltage and power factor (or phase angle) at the meter, but because they have limitations on how much data they can store and how much data capacity is available for transmission, utilities may choose not to program the meters to report these data. The other data elements described cannot be detected by most modern AMI systems. U.S. Pat. No. 7,948,255 to Coolidge, et al. discloses instruments for phase detection. However, the instruments in Coolidge are intended to be used by field engineers rather than incorporated into the Smart Grid.
The consensus among utilities is that the volatility of the LNM is such that using field engineers to measure and monitor changing attributes of the grid map is not a cost effective or workable solution. For example, conservation voltage regulation efforts were undertaken in the 1990s based on static measurements, and subsequently abandoned because the measurements became outdated too quickly. Today, utilities habitually oversupply consumers, delivering an average effective voltage of 122vAC to a 15 or 20 amp-rated circuit in a residence to ensure that fluctuations in load, power losses in the home wiring, etc. do not result in some consumers' service falling below 110vAC effective at individual outlets inside the building, which is generally the optimum for home appliances and the like. The goal of a well-instrumented fine-grained conservation voltage regulation system might be to reduce the typical effective voltage at a single-phase meter to 114vAC as measured from one leg of the typical 240vAC service to neutral. 114vAC effective at the meter is as low as it is reasonable to go without risking under-powering some outlets in the building, (i.e. not less than 110vAC at any outlet) due to additional losses which are typical inside the home or office.
Since electrical devices consume more energy when powered at the high end of their rated range, this practice of over-delivering impacts consumers' electric bills directly, as well as forcing generation-poor utilities to buy power, increasing their costs. Ultimately, the practice results in more fossil fuel being consumed than necessary.
Cost constraints also dictate that placing SCADA instrumentation at every medium-voltage field asset is impractical. The “touch points” on the distribution grid are, for better or worse, largely the meters at the edge and the instrumentation in the substations. This dictates that techniques for power line communication be revisited, because signals traveling on the power line can be used both to infer and to report grid mapping information not detectable by means of wireless AMI. The ubiquitous presence of wireless AMI for reporting meter data can be considered as a benefit in the search for effective grid-mapping technology, in that it frees the limited data-bearing capacity of low-frequency on-grid transmission methods to support grid mapping systems instead. It is, however, needful to identify a transmission method that is low cost at the edge, coexists with the AMR or AMI, and does not trigger any of the above-noted pitfalls of on-grid transmission: requirements for intermediate devices such as repeaters between the edge and the substation; unacceptable flicker; RF interference; impulse noise; etc. Finally, the transmission must require very little power, because the energy expended driving the transmitters reduces the energy conservation benefits obtained.
As discussed above, some existing PLC methods have adapted radio modulation techniques and channel access methods to the medium of the electrical distribution grid. For example, PRIME uses FDMA with DPSK.
In addition, Code Division Multiple Access (CDMA) is a channel access method most famously used in cellular telephony standards cdmaOne, WCDMA, and CDMA2000. CDMA spreads its signal across a range or band of frequencies, as do other similar technologies; hence the term broadband. Multiple access means that more than one transmitter can use the same channel (here, a power line) without the signal from one transmitter destructively interfering with the signal of another transmitter. In CDMA, each transmitter which uses the same band is assigned a distinct reference code or chip. The transmitted signal equals the exclusive OR (XOR) of the chip with the data signal. If the chips (treated as binary vectors) are mathematically orthogonal, then the receiver can separate out the several data signals from the additive received waveform. A requirement of standard CDMA as used in a wireless application is that there is a dynamic feedback loop from receiver to transmitter to ensure that the power of the several signals received from the different transmitters is the same or nearly the same at the receiver. The feedback loop permits the transmitters to rapidly and dynamically adjust their transmission power to maintain the balance.
Frequency Division Multiple Access (FDMA) means that multiple channels in a medium are created by having different transmitters use different frequencies (or different frequency bands). A signal injected on the power line creates harmonic signals of different amplitudes. If the frequency-division bands are incorrectly chosen, then the harmonics from different bands can coincide and create false signals that interfere destructively with the intended signals. The obvious means of eliminating this effect is to place the channels far apart on the frequency spectrum. This, however, reduces the overall data bearing capability of the medium by “wasting” spectrum.
A third channel access method is Time Division Multiple Access, or TDMA. In TDMA, the channel is divided cyclically over time, with each transmitter sharing the channel assigned a specific time slot in the cycle where that transmitter uniquely has permission to transmit. TDMA requires that all the transmitters have system clocks which are synchronized with one another within a close enough tolerance that one channel accessor does not overlap its transmission with that of another channel accessor.